The present invention relates to the field of oil and gas subsurface earth formation evaluation techniques and more particularly, to methods and an apparatus for determining reservoir properties of subterranean formations using quantitative refracture-candidate diagnostic test methods.
Oil and gas hydrocarbons may occupy pore spaces in subterranean formations such as, for example, in sandstone earth formations. The pore spaces are often interconnected and have a certain permeability, which is a measure of the ability of the rock to transmit fluid flow. Hydraulic fracturing operations can be performed to increase the production from a well bore if the near-wellbore permeability is low or when damage has occurred to the near-well bore area.
Hydraulic fracturing is a process by which a fluid under high pressure is injected into the formation to create and/or extend fractures that penetrate into the formation. These fractures can create flow channels to improve the near term productivity of the well. Propping agents of various kinds, chemical or physical, are often used to hold the fractures open and to prevent the healing of the fractures after the fracturing pressure is released.
Fracturing treatments may encounter a variety of problems during fracturing operations resulting in a less than optimal fracturing treatment. Accordingly, after a fracturing treatment, it may be desirable to evaluate the effectiveness of the fracturing treatment just performed or to provide a baseline of reservoir properties for later comparison and evaluation. One example of a problem occasionally encountered in fracturing treatments is bypassed layers. That is, during an original completion, oil or gas wells may contain layers bypassed either intentionally or inadvertently.
The success of a hydraulic fracture treatment often depends on the quality of the candidate well selected for the treatment. Choosing a good candidate for stimulation may result in success, while choosing a poor candidate may result in economic failure. To select the best candidate for stimulation or restimulation, there are many parameters to be considered. Some important parameters for hydraulic fracturing include formation permeability, in-situ stress distribution, reservoir fluid viscosity, skin factor, and reservoir pressure. Various methods have been developed to determine formation properties and thereby evaluate the effectiveness of a previous stimulation treatment or treatments.
Conventional methods designed to identify underperforming wells and to recomplete bypassed layers have been largely unsuccessful in part because the methods tend to oversimplify a complex multilayer problem and because they focus on commingled well performance and well restimulation potential without thoroughly investigating layer properties and layer recompletion potential. The complexity of a multilayer environment increases as the number of layers with different properties increases. Layers with different pore pressures, fracture pressures, and permeability can coexist in the same group of layers. A significant detriment to investigating layer properties is a lack of cost-effective diagnostics for determining layer permeability, pressure, and quantifying the effectiveness of a previous stimulation treatment or treatments.
These conventional methods often suffer from a variety of drawbacks including a lack of desired accuracy and/or an inefficiency of the computational method resulting in methods that are too time consuming. Furthermore, conventional methods often lack accurate means for quantitatively determining the transmissibility of a formation.
Post-frac production logs, near-wellbore hydraulic fracture imaging with radioactive tracers, and far-field microseismic fracture imaging all suggest that about 10% to about 40% of the layers targeted for completion during primary fracturing operations using limited-entry fracture treatment designs may be bypassed or ineffectively stimulated.
Quantifying bypassed layers has traditionally proved difficult because, in part, so few completed wells are imaged. Consequently, bypassed or ineffectively stimulated layers may not be easily identified, and must be inferred from analysis of a commingled well stream, production logs, or conventional pressure-transient tests of individual layers.
One example of a conventional method is described in U.S. Patent Publication 2002/0096324 issued to Poe, which describes methods for identifying underperforming or poorly performing producing layers for remediation or restimulation. This method, however, uses production data analysis of the produced well stream to infer layer properties rather than using a direct measurement technique. This limitation can result in poor accuracy and further, requires allocating the total well production to each layer based on production logs measured throughout the producing life of the well, which may or may not be available.
Other methods of evaluating effectiveness of prior fracturing treatments include conventional pressure-transient testing, which includes drawdown, buildup, injection/falloff testing. These methods may be used to identify an existing fracture retaining residual width from a previous fracture treatment or treatments, but conventional methods may require days of production and pressure monitoring for each single layer. Consequently, in a wellbore containing multiple productive layers, weeks to months of isolated-layer testing can be required to evaluate all layers. For many wells, the potential return does not justify this type of investment.
Diagnostic testing in low permeability multilayer wells has been attempted. One example of such a method is disclosed in Hopkins,. C. W., et al., The Use of Injection/Falloff Tests and Pressure Buildup Tests to Evaluate Fracture Geometry and Post-Stimulation Well Performance in the Devonian Shales, paper SPE 23433, 22-25 (1991). This method describes several diagnostic techniques used in a Devonian shale well to diagnose the existence of a pre-existing fracture(s) in multiple targeted layers over a 727 fit interval. The diagnostic tests include isolation flow tests, wellbore communication tests, nitrogen injection/falloff tests, and conventional drawdown/buildup tests.
While this diagnostic method does allow evaluation of certain reservoir properties, it is, however, expensive and time consuming—even for a relatively simple case having only four layers. Many refracture candidates in low permeability gas wells contain stacked lenticular sands with between 20 to 40 layers, which need to be evaluated in a timely and cost effective manner.
Another method uses a quasi-quantitative pressure transient test interpretation method as disclosed by Huang, H., et al., A Short Shut-In Time Testing Methodfor Determining Stimulation Effectiveness in Low Permeability Gas Reservoirs, GASTIPS, 6 No. 4, 28 (Fall 2000). This “short shut-in test interpretation method” is designed to provide only an indication of pre-existing fracture effectiveness. The method uses log-log type curve reference points—the end of wellbore storage, the beginning of pseudolinear flow, the end of pseudolinear flow, and the beginning of pseudoradial flow—and the known relationships between pressure and system properties at those points to provide upper and lower limits of permeability and effective fracture half length.
Another method uses nitrogen slug tests as a prefracture diagnostic test in low permeability reservoirs as disclosed by Jochen, J. E., et al., Quantifying Layered Reservoir Properties With a Novel Permeability Test, SPE 25864,12-14 (1993). This method describes a nitrogen injection test as a short small volume injection of nitrogen at a pressure less than the fracture initiation and propagation pressure followed by an extended pressure falloff period. Unlike the nitrogen injection/falloff test used by Hopkins et al., the nitrogen slug test is analyzed using slug-test type curves and by history matching the injection and falloff pressure with a finite-difference reservoir simulator.
Similarly, as disclosed in Craig, D. P., et al., Permeability, Pore Pressure, and Leakoff-Type Distributions in Rocky Mountain Basins, SPE PRODUCTION & FACILITIES, 48 (February, 2005), certain types of fracture-injection/falloff tests have been routinely implemented since 1998 as a prefracture diagnostic method to estimate formation permeability and average reservoir pressure. These fracture-injection/falloff tests, which are essentially a minifrac with reservoir properties interpreted from the pressure falloff, differ from nitrogen slug tests in that the pressure during the injection is greater than the fracture initiation and propagation pressure. A fracture-injection/falloff test typically requires a low rate and small volume injection of treated water followed by an extended shut-in period. The permeability to the mobile reservoir fluid and the average reservoir pressure may be interpreted from the pressure decline. A fracture-injection/falloff test, however, may fail to adequately evaluate refracture candidates, because this conventional theory does not account for pre-existing fractures.
Thus, conventional methods to evaluate formation properties suffer from a variety of disadvantages including a lack of the ability to quantitatively determine the reservoir transmissibility, a lack of cost-effectiveness, computational inefficiency, and/or a lack of accuracy. Even among methods developed to quantitatively determine a reservoir transmissibility, such methods may be impractical for evaluating formations having multiple layers such as, for example, low permeability stacked, lenticular reservoirs.